Hydrocarbon production starts with mining. Either surface mining with large cranes and trucks used for oil sands mining or drilling a well to mine the hydrocarbons in a subsurface formation. In either case, byproducts from mining, drilling, completing and/or producing hydrocarbons range from drill cuttings to frack flowback water to produced water and huge volumes of tailings in the case of oil sands surface mining (collectively referred to as “mining byproducts”).
Solvents and/or valuable drilling fluids (collectively referred to as “mining fluids”) are used in the mining or drilling process to, among other things, provide hydrostatic pressure, cool and clean the drill bit, carry out drill cuttings (e.g., rock, soil, sand, etc.), and suspend the drill cuttings when the drill is not active. The cost of most drilling fluids is directly proportional to the cost of crude oil. Hence, oil based muds (“OBM”) are predominantly diesel, and synthetic based muds (“SBM”) are synthetic oils similar to Shell Rotella®. For example, formate drilling fluids manufactured by Cabot Corporation are extremely expensive but are environmentally safe, do not contain solids and can be used within high temperature and high pressure formations. Likewise, synthetic based drilling fluids are commonly employed for offshore drilling because the drill cuttings can be discharged overboard as long as the Fluid Retention On Cuttings (“ROC”) is less than what is required by regulations.
The mixture of mining fluids and mining byproducts that exit the mine or well also contain hydrocarbons. This mixture is typically processed by a solids control system (e.g., shale shakers, mud gas separators, desanders, desilters, degassers, cleaners, etc.) to substantially separate the mining fluids and hydrocarbons from the mining byproducts. But these solids control systems do not remove all of the mining fluids and hydrocarbons from the mining byproducts. As a result, these valuable mining fluids and hydrocarbons may end up in a tailings pond, the bottom of the ocean or shipped to a Treatment, Recovery and Disposal (“TRD”) facility.
Vertical Centrifuges are commonly employed offshore for reducing the ROC to below discharge limits. However, Loss Circulation Material (“LCM”) and cement cannot be effectively treated in a vertical centrifuge. It clogs the centrifuge and it must be shut down and cleaned, thus it is usually bypassed during cementing operations or when a LCM Pill is used to prevent losing circulation and fluids into the formation. Another treatment system uses thermal desorption units, which are bulky and have many moving parts. Likewise, thermal desorption units typically employ indirect heating, which is inefficient when compared to direct heating.
Air dryers and friction dryers, such as Schlumberger's (M-I Swaco) Hammermill are commonly employed, but neither have been successful at recovering base fluids. Why? Both dryer types comminute the cuttings into very fine powders which makes it difficult to separate the base fluid from the fine cuttings. Likewise, air dryers can produce an explosive mixture since drilling fluids contain fuels (diesel, synthetic oil, etc.). Although Schlumberger markets a Zero Discharge thermal desorption TPS system, the system still only achieves a removal of Total Percent Hydrocarbons (TPH) of less than 0.5%. Finally, the U.S. Department Of Energy's Drilling Waste Management Information System discloses many different thermal technologies for treating drilling waste.
When the price of crude oil was low, a ROC near the limits was not perceived as a problem. However, with new regulations pushing lower ROC limits in addition to high crude oil prices, recovering mining fluids from the mining byproducts has become a priority and is now an environmentally sustainable goal for many oil and gas companies. Moreover, the cost of some mining fluids, such as formate drilling fluids containing Cesium, makes recovering these mining fluids from the mining byproducts very desirable both economically and ecologically.
Other problems associated with the production of oil and gas resources include the fact it is very common for oil production wells to reach the end of their life, while there is still a substantial amount of oil in place (OIP) within the formation. Production superintendents, Geologists and Engineers may then to decide whether to shut in the well or stimulate the well using enhanced oil recovery (EOR) methods ranging from water flooding to steam flooding to injection of carbon dioxide and injection of solvents.
Likewise, even during peak production of a well, a well may have to be shut in due to paraffin plugging the production tubing. This can cause several problems ranging from reduced production to parting or breaking of the sucker rod connected to the surface pump jack. Another problem associated with most oil and gas wells is produced water. When the water reaches the surface it is separated from the oil or gas and then must be treated prior to final disposition.
Recently, primarily due to high crude oil prices many exploration companies are turning to unconventional heavy oil resources (API<22) such as oil sand bitumen, oil shale kerogen as well as heavy oil itself. Canada contains the largest known oil sand reserves estimated at over 1 trillion recoverable barrels of bitumen. Likewise, the largest known unconventional petroleum or hydrocarbon resource can be found in the Green River Formation in Colorado, Wyoming and Utah. Worldwide oil shale reserves are estimated around 2.9-3.3 trillion barrels of shale oil while the Green River Formation reserves alone are estimated to contain between 1.5-2.6 trillion barrels.
However, emerging issues with respect to the renewed interest in oil shale development range from water resources, to green house gas emissions to basic infrastructure needs. Likewise, the Canadian oil sands has its own problems ranging from very large tailings ponds to a lack of upgrading capacity for the bitumen recovered from the oil sands. In addition, the steam assisted gravity drainage (SAGD) process utilizes copious amounts of energy to produce steam. Two problems associated with producing steam are first the source of water and removing its contaminants that may be deposited upon boiler tube walls and second recovering the latent heat within the steam when injected downhole.
The problem is indirect heat transfer. Heat is transferred via radiation, convection and conduction. Indeed, SAGD evaporators and boilers transfer heat via radiation, convection and conduction. Although the flame in the boiler transfers heat via radiation and convection to boiler tubes, heat transfer through boiler tubes is solely via thermal conduction. And the impediment to reducing production costs at SAGD facilities is heat transfer via thermal conduction through boiler tubes.
When the heat transfer surface of the boiler tubes becomes coated with contaminants, for example silica, then heat transfer is reduced and the boiler and/or evaporator must be shut down for maintenance. At SAGD facilities this is a common problem, especially with silica, and is now being viewed as non-sustainable. The silica is produced with the oil sand. Hence, sand contamination via volatile silica compound evaporation, as well as volatile organic compounds (“VOCs”) is an inherit problem in current EOR operations utilizing traditional water treatment methods with boilers and once through steam generation equipment.
Therefore, a need exists for systems, methods and apparatuses to treat mining byproducts and provide enhanced oil recovery.